U.S. patent application number 12/811650 was filed with the patent office on 2011-04-21 for monitoring system for pipelines or risers in floating production installations.
Invention is credited to Dominic McCann, Daniel Sack, Morten Stenhaug.
Application Number | 20110088910 12/811650 |
Document ID | / |
Family ID | 39111228 |
Filed Date | 2011-04-21 |
United States Patent
Application |
20110088910 |
Kind Code |
A1 |
McCann; Dominic ; et
al. |
April 21, 2011 |
MONITORING SYSTEM FOR PIPELINES OR RISERS IN FLOATING PRODUCTION
INSTALLATIONS
Abstract
A method of monitoring a subsea pipeline system connecting one
or more wells to a floating production system, wherein the pipeline
system is at least partially flexible, the method comprises
installing a continuous optical fibre distributed sensor as part of
the pipeline system, the sensor capable of providing a distributed
measurement of temperature, vibration, pressure or strain, or any
combination thereof; using the sensor to obtain a distributed
measurement of temperature, vibration, pressure and/or strain along
at least part of the pipeline system indexed to a length thereof;
and using the distributed measurement to predict the actual
condition of the fluid, the pipeline system and/or the adjacent sea
water using a model. A subsea pipeline system for connecting one or
more wells to a floating production system, wherein the pipeline
system comprises at least one partially flexible pipeline; a
continuous optical fibre distributed sensor installed as part of
the pipeline capable of providing a distributed measurement of
temperature and/or strain; means for obtaining a distributed
measurement of temperature, vibration or strain, or combinations
thereof, along at least part of the pipeline system indexed to a
length thereof from the sensor; and means for using the distributed
measurement to manage operation of the system. Preferably, the
system comprises means for modelling expected pipeline behaviour
using the distributed measurement as an input; and means for using
the modelled behaviour to manage operation of the system.
Inventors: |
McCann; Dominic; (Romsey,
GB) ; Sack; Daniel; (Singapore, SG) ;
Stenhaug; Morten; (Sandsll, NO) |
Family ID: |
39111228 |
Appl. No.: |
12/811650 |
Filed: |
January 7, 2009 |
PCT Filed: |
January 7, 2009 |
PCT NO: |
PCT/GB09/00025 |
371 Date: |
January 10, 2011 |
Current U.S.
Class: |
166/344 ;
702/183; 702/25 |
Current CPC
Class: |
E21B 19/002 20130101;
E21B 19/004 20130101; E21B 17/01 20130101 |
Class at
Publication: |
166/344 ; 702/25;
702/183 |
International
Class: |
E21B 43/01 20060101
E21B043/01; G06F 19/00 20110101 G06F019/00; G06F 15/00 20060101
G06F015/00 |
Foreign Application Data
Date |
Code |
Application Number |
Jan 8, 2008 |
GB |
0800241.2 |
Claims
1. A method of monitoring a subsea pipeline system connecting one
or more wells to a floating production system, wherein the pipeline
system is at least partially flexible, the method comprising:
installing a continuous optical fibre distributed sensor as part of
the pipeline system, the sensor capable of providing a distributed
measurement of temperature, vibration, pressure or strain, or any
combination thereof; using the sensor to obtain a distributed
measurement of temperature, vibration, pressure and/or strain along
at least part of the pipeline system indexed to a length thereof;
and using the distributed measurement to predict the actual
condition of the fluid, the pipeline system and/or the adjacent sea
water using a model.
2. A method as claimed in claim 1, wherein the method comprises
modelling expected pipeline behaviour using the distributed
measurement as an input; and using the modelled behaviour to manage
operation of the system.
3. A method as claimed in claim 2, wherein the model estimates
fatigue in the pipeline system, and/or the likelihood of hydrate or
wax deposits at locations in the pipeline system.
4. A method as claimed in claim 2 or 3, wherein modelled behaviour
is used to determine operation control parameters of the system,
including heating zones of the pipeline system, shut-down/cool-down
periods, choke positions and tension in anchor chains.
5. A method as claimed in any preceding claims, further comprising
making discrete measurements and using these discrete measurements
to predict the actual condition of the fluid, the pipeline system
and/or the adjacent sea water.
6. A method as claimed in claim 5, wherein the discrete
measurements comprise flow rate measurements in the pipeline and/or
at the surface on the floating production system.
7. A method as claimed in any preceding claim wherein the step of
installing a continuous optical fibre distributed sensor comprises
embedding the fibre in the wall of the pipeline, fixing the fibre
to the inner or outer wall of the pipeline, or locating the fibre
in a conduit in the pipeline.
8. A method as claimed in any preceding claim, comprising using
Brillouin backscatter measurements to provide distributed strain
and temperature measurements.
9. A method as claimed in any preceding claim, comprising using
coherent Rayleigh noise for vibration monitoring.
10. A method as claimed in any preceding claim, comprising linking
the measurements with the model for prediction and control in
real-time.
11. A method as claimed in any preceding claim for use in a flow
assurance programme.
12. A method as claimed in any preceding claim for use in a marine
structural integrity programme.
13. A subsea pipeline system for connecting one or more wells to a
floating production system, wherein the pipeline system comprises:
at least one partially flexible pipeline; a continuous optical
fibre distributed sensor installed as part of the pipeline capable
of providing a distributed measurement of temperature and/or
strain; means for obtaining a distributed measurement of
temperature, vibration or strain, or combinations thereof, along at
least part of the pipeline system indexed to a length thereof from
the sensor; and means for using the distributed measurement to
manage operation of the system.
14. A system as claimed in claim 13, further comprising means for
modelling expected pipeline behaviour using the distributed
measurement as an input, and means for using the modelled behaviour
to manage operation of the system.
15. A system as claimed in claim 14 or 15, wherein the pipeline is
a flexible riser or subsea flowline.
16. A system as claimed in claim 13, 14 or 15, wherein the optical
fibre sensor uses Raman backscattered Stokes and anti-Stokes
measurements for temperature determination, Brillouin backscatter
for temperature and strain determination, or coherent Rayleigh
noise for vibration monitoring.
17. A system as claimed in any of claims 13-16, wherein the optical
fibre is deployed in a U-shaped configuration with both ends
located at or near the surface end of the pipeline.
18. A system as claimed in any of claims 13-17, wherein the optical
fibre is embedded in the wall of the pipeline, fixed to the inner
or outer wall of the pipeline, or located in a conduit in the
pipeline.
Description
TECHNICAL FIELD
[0001] This invention relates to monitoring systems for use in
floating production installations such as those used in offshore
oil and gas production. In particular, the invention relates to the
use of distributed fibre optic sensors to provide information
allowing effective management of such production systems.
BACKGROUND ART
[0002] Subsea oil and gas production is growing in importance and
is expected to increase significantly in the next 5 to 10 years. In
addition, offshore fields are being exploited in deeper and deeper
water depths. Floating Production, Storage and Offloading (FPSO)
systems are sometimes used to collect the oil and/or gas produced
by one or more wells or platforms in an offshore field, process it
and store it until it can be offloaded into a tanker or pipeline
for transport to land-based facilities. One common approach to
FPSOs is to use a decommissioned oil tanker which has been stripped
down and re-equipped with facilities to be connected to a mooring
buoy and to process and store oil delivered from the wells or
platforms. The oil and/or gas is delivered from the well or
platform to the FPSO by means of risers, flowlines or export lines
connected through a mooring buoy.
[0003] Oil and gas production using a FPSO presents many challenges
which increase as the water depth increases. For instance, one
problem is that the lines used to transfer the oil or gas from a
wellhead situated on the seabed to the FPSO are subject to tidal
and water current movements and to motions associated with the
effects of sea conditions on the FPSO, and therefore can suffer
from fatigue or damaging vibrations. Another problem is that the
temperature of the oil or gas in the line can change as flow
conditions in the line change. As a result at low temperatures,
waxes or hydrates can be deposited on the inside of the lines. This
is a serious problem especially when, oil or gas production is
stopped during shut-in periods. Then the temperature of the oil or
gas in the line will cool as a result of heat loss to the
surrounding much cooler sea water. In order to prevent hydrates
from forming in the lines, some operators have been heating the
lines during shut-in periods which are rather costly. Others have
been keeping shut-in times too short making maintenance
inefficient.
[0004] Previous attempts to address these issues have involved
modelling of the expected flow-line behaviour and using the results
of the modelling to determine insulation and/or heating
requirements of the line or maintenance schedules to minimize
structural issues. However, these models make many assumptions
about the environmental conditions and the pressure and temperature
cycles, and in order to reduce the probability of system failure,
conservative values or value ranges are applied. This results in
costly inefficiencies, overly conservative behaviour and higher
running costs. For example, flowlines are often insulated and/or
heated to higher temperatures than are necessary which results in
additional running costs. Furthermore, shut-in periods are often
reduced in time, making it difficult to achieve critical
maintenance in one shut-in.
[0005] Optical interrogation of fibres is a technology that has
been available for many years and there are several commercial
applications. In particular, Distributed Temperature Sensing (DTS)
which makes use of the Raman backscattered Stokes and anti-Stokes
wavelengths (see Brown, G. A. "Monitoring Multi-layered Reservoir
Pressures and GOR Changes Over Time Using Permanently Installed
Distributed Temperature Measurements", SPE 101886, September 2006)
can provide a distributed temperature measurement along the fibre.
This has been used in fire detection applications, power line
monitoring and downhole applications. It has also been used on a
flexible riser on the subsea platforms or flexible risers connected
to an FPSO. Other known techniques for optical interrogation of
fibres are the Brillouin and coherent Rayleigh noise (CRN)
measurements.
[0006] The present invention provides an improved method and system
for monitoring the behaviour of subsea lines, such as risers or
pipelines. The invention employs distributed measurements with
modelling to provide continuous and distributed prediction of
subsea line behaviour.
DISCLOSURE OF INVENTION
[0007] A first aspect of the invention provides a method of
monitoring subsea lines connecting one or more wells to a floating
production system. The subsea lines can be of many different types.
Preferred subsea lines are those that are partially or wholly
flexible or compliant, and most preferred are compliant-type subsea
lines. However, preferably the subsea lines or line system is at
least partially flexible or compliant, the method comprising:
[0008] installing a continuous optical fibre distributed sensor as
part of the pipeline system, the sensor capable of providing a
distributed measurement of temperature, vibration or strain, or
combinations thereof; [0009] using the sensor to obtain a
distributed measurement of temperature, vibration and/or strain
along at least part of the pipeline system indexed to a length
thereof; [0010] using the distributed measurement to predict the
actual condition of the fluids, the pipeline system and/or the
adjacent sea water using a model.
[0011] It is preferred that the method comprises modelling expected
pipeline behaviour using the distributed measurement as an input;
and using the modelled behaviour to manage operation of the
system.
[0012] Preferably, the model estimates fatigue in the pipeline
system, and/or the likelihood of hydrate or wax deposits at
locations in the pipeline system.
[0013] The modelled behaviour can be used to determine operation
control parameters of the system, including heating zones of the
pipeline system, shut-down/cool-down periods, choke positions and
tension in anchor chains.
[0014] The method can also include making discrete measurements
such as flow rate measurements in the pipeline and/or at the
surface on the floating production system and using these to
predict the actual condition of the fluid, the pipeline system
and/or the adjacent sea water.
[0015] Preferably the step of installing a continuous optical fibre
distributed sensor comprises embedding the fibre in the wall of the
pipeline, fixing the fibre to the inner or outer wall of the
pipeline, or locating the fibre in a conduit in the pipeline.
[0016] The method can comprise using Raman measurements to obtain a
distributed temperature measurement, Brillouin backscatter
measurements to obtain distributed strain and temperature
measurements, and/or coherent Rayleigh noise to obtain distributed
vibration measurements.
[0017] The methods according to the invention can be used in flow
assurance programmes and marine structural integrity programmes.
The measurements can be linked to the models for prediction and
control in real-time.
[0018] A second aspect of the invention comprises a subsea pipeline
system for connecting one or more wells to a floating production
system, wherein the pipeline system comprises: [0019] at least one
partially flexible or compliant pipeline; [0020] a continuous
optical fibre distributed sensor installed as part of the pipeline
capable of providing a distributed measurement of temperature
and/or strain; [0021] means for obtaining a distributed measurement
of temperature, vibration or strain, or combinations thereof, along
at least part of the pipeline system indexed to a length thereof
from an output of the sensor; and [0022] means for using the
distributed measurement to manage operation of the system.
[0023] Preferably, the system comprises means for modelling the
expected pipeline behaviour using the distributed measurement as an
input, and means for using the modelled behaviour to manage
operation of the system.
[0024] The pipeline is typically a flexible or compliant riser or
subsea flowline.
[0025] The optical fibre sensor can use Raman backscattered Stokes
and anti-Stokes measurements for temperature determination,
Brillouin backscatter for temperature and strain determination, or
coherent Rayleigh noise for vibration monitoring.
[0026] The optical fibre may further be deployed in a U-shaped
configuration with both ends located at or near the surface end of
the pipeline. The fibre can be embedded in the wall of the
pipeline, fixed to the inner or outer wall of the pipeline, or
located in a conduit in the pipeline.
BRIEF DESCRIPTION OF FIGURES IN THE DRAWINGS
[0027] FIG. 1 shows a schematic view of a FPSO system;
[0028] FIG. 2 shows an installation of an optical fibre sensor;
and
[0029] FIGS. 3 and 4 show distributed temperature measurements in a
pipeline.
MODE(S) FOR CARRYING OUT THE INVENTION
[0030] The present invention provides methods and systems that
address the problems indicated above in relation to prior art
systems and other issues that can be prevented or better managed by
continuous and distributed monitoring of the risers and/or
pipeline. The invention can provide both continuous flow assurance
and structural monitoring with feed back of measured parameters
into original design models in order to manage operations. A
schematic FPSO system is shown in FIG. 1 and comprises the FPSO
vessel 10 which is anchored to the sea bed by anchor chains 12. A
tanker offloading buoy 14 is connected to the FPSO 12 by means of a
flexible offloading pipeline 16. Further flexible flowlines 18
connect the FPSO 10 to nearby platforms 20 to allow direct
production to the FPSO 10. Also, existing subsea wells 22 have
connections to subsea manifolds 24 from which flexible flowlines 18
and risers 26 lead to connect to the FPSO 10.
[0031] This invention proposes the use of fibre optics to provide a
distributed measurement system which is used to calibrate models so
that system behaviour is more accurately predicted thus removing
the uncertainty of present day practices so that operations can be
optimized. The system may also incorporate discrete measurements on
the risers or pipelines, for example, fibre Bragg gratings and
surface fluid flow rates. It is the combination of these
measurements and system models which provide a methodology which is
particularly preferred.
[0032] The combination of these measurements with feed back into
design models will allow the following the following example
diagnosis:
[0033] For flow assurance: [0034] Assess burial of the lines and
contribution to insulation; [0035] Assess insulation performance;
[0036] Determine cold points; [0037] Optimize process
operations/heating requirements during shut-down/cool-down periods;
[0038] Optimize the time required for such shut-down/cool-down
periods; [0039] Determine hydrate blockage location; [0040]
Determine hydrate/wax inhibitor quantities and flow rates; [0041]
Determine deposits (wax, scales) location due to local abnormal
pressure, temperature and/or strain profiles; and/or [0042]
Slugging flow in the line detected through vibrations or dynamic
strain measurements.
[0043] For marine/structural integrity: [0044] Determine effect of
shut down and/or pressure cycles on line stresses/movements, e.g.,
`pipe walking` effect for injection lines and lateral buckling for
production lines. [0045] Assess riser and line fatigue. [0046]
Assess free span & upheaval buckling. [0047] Assess vortex
induced vibrations (VIV). [0048] Potentially assess corrosion
through strain profile changes.
[0049] These are just examples of system diagnoses which are
possible.
[0050] There are further preferred aspects of this invention which
are described below.
[0051] An optical fibre is preferably deployed along the length of
the riser or pipeline. This can be achieved by embedding it within
the wall of the pipeline or by strapping/clamping it to the inner
or outer wall of the line. Another possible deployment mechanism is
to provide a control line or conduit within the wall of the
pipeline or again strapped to the inner or outer wall of the line.
Once the riser or pipeline is deployed, the fibre can be pumped
into this control line so that the fibre traverses the length of
the line. The method is described in U.S. Pat. No. 5,570,437. If
the fibre is to be used to measure strain in the line then it will
need to be mechanically coupled to the riser or pipeline so that
strain on the line is transferred to the fibre.
[0052] In one aspect of the invention, the control line is a
continuous `U` as shown schematically in FIG. 2. In this case, a
pair of conduits 30 are provided, connected at their lower ends by
a turn around sub 32 and attached to the inner or outer wall of the
pipeline 34 (or disposed within the wall of the pipeline 34). The
fibre 36 may be pumped in one end of the conduit 30, along its
length and then all the way back so that both ends of the fibre are
available at the FPSO 38 and can be interrogated by pulsing light
down either side. This provides more accuracy when it is used for
distributed temperature measurement and can also provide redundancy
should the fibre break at some point. Finally, many flow-lines
already have fibres installed within them for data transmission
purpose. These fibres are generally single mode fibres and one
embodiment of this invention is to interrogate such fibres using
Brillouin scattering so that the temperature and strain can be
measured along the fibre. This provides a retrofit methodology
allowing the system to be applied to existing infrastructure. The
same fibre can be used for distributed temperature, strain,
vibration and dynamic strain measurements. Also, existing fibre
lines used for communication could also be used for sensing
purposes for example by interrogating them at a different
wavelength or wavelengths from the ones used for communications;
such different wavelength being suitable for sensing purposes.
[0053] The installed fibre can be interrogated using either Raman
DTS for temperature distribution, Brillouin backscatter for
temperature and strain or coherent Rayleigh noise for vibration
monitoring, or any combination of these measurements. A high
frequency Brillouin system can be used to provide a dynamic strain
measurement. These distributed measurements can be combined with
single point electric or fibre measurements of temperature, strain,
flow, pressure or other parameters which can be relevant to
determining the status of the system.
[0054] Interpretation that includes models calibrated using the
measured data can be used to predict the status of the system.
However, the measurements in themselves can be extremely useful in
optimizing the system. A particular example is shown in FIGS. 3 and
4. These plots show the temperature along a flexible riser from
surface at length 0 to the bottom of the line at the centre of the
plot and back to surface as shown. FIG. 3 shows the temperature
along a flexible riser before the heating elements on the line are
switched on. Fluid is being pumped through the line but the line
temperature is not controlled.
[0055] On the other hand, FIG. 4 shows the temperature along the
line while fluid is being pumped in the line and once the heating
elements are switched on. The plot clearly shows the point at with
the flexible riser `touches down` on the seabed and is partially or
totally buried. From this point on the line to the lower point of
the riser, the temperature increases due to the fact that heat loss
to the seawater from this point onwards is reduced. The use of this
data allows the heating of this part of the line to be reduced
without risking its temperature being below a point where hydrates
will form. By segmenting the line into sections and using the
measured temperature along these sections, the heating of each
section can be controlled to optimize the line temperature and thus
reduce power required and reduce the running costs of the system. A
few degrees of heating on such lines can represent a significant
cost. The data can also be used to manage the shut-down/cool-down
period, thus improving the efficiency of maintenance activities and
allowing more to be achieved during a single shut-down.
[0056] The results from the measurements and interpretations are
used to control system parameters such as riser heating as
described above. Another example of an operational parameter that
can be managed in this way is the tensioning of the anchor chains
to control excessive vibration of the riser.
[0057] The modelling and interpretation can be performed on the
FPSO or data from the measurements can be transmitted to a remote
control centre which can be anywhere in the world. Such a centre
can receive data from many installations potentially worldwide and
undertake analysis of the information and model outputs. This will
allow determination of the actions to be taken as a result of the
model outputs. In some cases these actions can be automated.
[0058] One example is using an existing flow assurance model such
as the well-known OLGA flow assurance model which uses pressure and
temperature data to predict the likelihood of hydrate or wax
formation in the line. The present invention system and method
provides for collecting a plurality of temperature and pressure
data along the entire or selected portions of the conduit using a
distributed fibre sensor, feeding these data into a model to
accurately predict the location of any possible hydrates and wax
formation along the pipeline and taking localized corrective action
as needed. For example, in a conduit comprising a plurality of
heating elements selectively activating certain elements to control
the temperature at a desired level can prevent hydrate and/or wax
formation and avoid expensive shut-downs.
* * * * *